Corrosion of processed metals, such as steel, copper, and zinc, is a process whereby elemental metals, in the presence of water and oxygen, are converted to oxides. Although corrosion is a complicated process, it may be considered an electrochemical reaction involving three steps which occur at the anodic and cathodic sites of a metal surface, as follows:
1. Loss of metal to the water solution in oxidized cationic form at an anodic site, with concomitant release of electrons ("anodic reaction"); PA1 2. The flow of the released electrons to a cathodic site; and PA1 3. Oxygen at a cathodic site uses the electrons to form hydroxyl ions ("cathodic" reaction), which flow to an anodic site.
These basic steps are necessary for corrosion to proceed, and the slowest of the three steps determines the rate of the overall corrosion process.
A corrosion control program usually depends on specific inhibitors to stop the anodic reaction, slow the cathodic reaction, or both. Among the various types of corrosion inhibitors are organic filmers, which act by forming filming layers on metal surfaces to separate the water and metal. These materials form and maintain a barrier between the water and metal phases to prevent corrosion.
In most any system employing corrosion inhibitors, the ability to monitor the concentration of corrosion inhibitor in the system would enable one to better control the dosage of corrosion inhibitor. Active corrosion inhibitor components may be consumed in the inhibition process or lost due to deposit, corrosion and chemical degradation processes and combinations of such phenomena. Monitoring the depletion of an active corrosion inhibitor component, particularly if such monitoring permits the extent of depletion to be quantified, is an indicator of treatment program performance. Moreover, if the monitoring results are obtained rapidly and the active component depletion is precisely determined, the monitoring also permits the corrosion inhibitor dosage to be accurately controlled and quickly corrected when necessary.
The need to monitor corrosion inhibitor concentration in an aqueous system is very acute when the system is a large aqueous system, such as the aqueous systems of oil fields. Petroleum reservoirs can vary in length and width from about one to several miles, and in depth from a few feet to several hundred feet. Petroleum is produced first by penetration of a reservoir by a drill, the natural reservoir pressure forcing oil and gas to the surface. Such primary production continues for a period of a few months or several years. The oil leaving a producing well is a mixture of liquid petroleum, natural gas and formation water. During early primary production, the water fraction may be insignificant. Most production thereafter, however, contains sizable proportions of produced water (up to about 90%), generally either as "free water" (which separates from the liquid petroleum in about 5 minutes) or emulsified water. Such post-primary additional production of oil is accomplished using one or more enhanced recovery methods, such as waterflooding, gas injection, and other processing involving fluid or energy injection for secondary or tertiary oil recovery.
Waterflooding, for instance, involves the injection of water as a uniform barrier through the producing formation from a series of injection wells toward a producing well. Such injection wells may be distributed throughout a reservoir or they may be placed at its periphery. During any enhanced recovery processing, formation water is generally being produced, but in waterflooding processes the amount of flood water used often far exceeds the volume being produced. The produced water, together with supplemental surface water, is also generally processed before its use as injection water, by such methods as filtration, clarification, deaeration, chemical addition and the like.
Steam and carbon dioxide flooding also use large amounts of water. Steam flooding, for instance, involves either the injection of steam for a time period during which the well is taken out of service, or the introduction of a steam-water mixture through a displacement well, from which site the steam and hot water radiate outward toward peripheral oil wells.
Oil field applications not only involve vast amounts of water, they also employ vast amounts of metal conduits and the like that come into contact with such waters. A flowing oil well is generally constructed of "strings" of concentric vertical pipes called casings, and smaller pipes, usually 2 to 3 inches in diameter, called tubing, through which produced fluid flows. The largest diameter casing (the surface string) typically extends to a depth of from about 200 to about 1500 feet, while the intermediate string may reach a depth of up to 5,000 feet, and a third casing (the oil string) may reach the producing zone. Some producing zones are at depths of 20,000 feet or more. A series of valves and flanges at the wellhead control flow. When the natural reservior energy subsides, some method of pumping is also employed.
Oil fields thus routinely employ large volumes of water and have an immense surface area of pipes, tubes, and other metal fixtures and components in regular contact with such waters that must be protected from corrosion. The primary corrodents in oil field water systems are carbon dioxide, hydrogen sulfide and oxygen. One reason oxygen is corrosive, even at low temperatures, is its participation in creating differential cells beneath deposits on metal surfaces, which become anodic to adjacent deposit-free areas. Control of oxygen corrosion in oil field water systems requires a conscientious effort to exclude air from all surface tanks and vessels and from the casings of producing wells. When hydrogen sulfide is present, iron sulfide deposits, and these deposits are cathodic to base metal. Severe pitting can occur beneath iron sulfide deposits, and if oxygen intrudes into a sulfide system the rate of corrosion can become uncontrollable. Invariably, corrosion inhibitors used in oil field water are organic film formers.
In wells producing a significant crude phase, a corrosion inhibitor that is oil soluble and only slightly water dispersible is often employed. Such corrosion inhibitor will film metal from the oil phase, providing long-term persistency to the metal surface and thus often requiring only intermittent batch feeding of the corrosion inhibitor to the formation down the tubing or into the annulus. In injection water or other systems where water is a significant phase, however, corrosion inhibitors must be either totally water soluble or highly water dispersible to carry through the surface line and tubing system. These corrosion inhibitors generally are not persistent, and it is necessary to feed them continuously, always maintaining a residual amount in the system. Loss of corrosion inhibitor residuals results in desorption of inhibitor film and loss of protection.
Since maintaining corrosion inhibitor residuals is critical to maintaining protection in injection water systems, and in any system having a predominant or significant water phase, inhibitor residuals are routinely determined in the field to provide close control. The currently used method is a procedure wherein the amine-type compounds present in a water sample are first extracted, and then the concentration of these compounds are determined colorimetrically. This and other known procedures are discussed in more detail below.
It would be highly desirable to provide a method for monitoring water soluble corrosion inhibitor concentration in the waters of injection water systems and other large aqueous systems that is faster than current methods. It would be highly desirable to provide such a monitoring method that provides real-time analysis, detecting any corrosion inhibitor underfeeding in time to permit system changes before real corrosion damage occurs. It would be highly desirable to provide such a monitoring method that is product specific, focussing only the compound of interest, and avoiding interferences from other compounds. It would be highly desirable to provide such a monitoring method that directly analyzes one of the "actives" that provide the corrosion protection, instead of an inert dye or other tracer compound that does not behave chemically similar to the corrosion inhibitor product. It would be highly desirable to provide such a monitoring method that determines corrosion inhibitor actives precisely, while maintaining the desired speed and product specificity. It is an object of the present invention to provide such a method with aforesaid highly desirable advantages over current methods of monitoring corrosion inhibitors, and by virtue of such fast, specific and precise monitoring also provide a method for controlling the dosage of corrosion inhibitor for such systems. The invention and these and other objects and advantages of the invention are described in more detail below.